Oil, gas and other types of wells are typically excavated and completed using rotary drilling technology. For example in a near-vertical wellbore, drilling is typically accomplished by a rotary drill bit hung on a drill string which is rotated from a surface mounted rotary table or other means for inducing rotary motion.
In near-vertical wells, the rotary drag due to frictional contact between the drill string (excluding the drill bit) and the wellbore is typically not large when compared to the rotary forces at the drilling face. Rotary wellbore drag of the drill string is therefore easily overcome by the rotary means typically associated with rotary drilling a near-vertical wellbore.
However, rotary drag at the drill bit can cause significant problems in near-vertical wells and drill bit and drill string problems in extended reach wells. A major problem affecting the life and performance of drag-type drill bits, e.g., PDC drill bits, is "bit whirl," the tendency of a drill bit to wobble off-center while rotating. Bit whirl is due, at least in part, to unequal rotary drag forces acting on the bit's outside diameter or gauge pads. Even a small amount of bit wobble can lead to an unequal distribution of forces on the cutters, causing premature failure or accelerated wear of one or more cutters and drill string damage. Conventional corrective measures, such as using low friction gauge materials and/or other bit gauge modifications, have not eliminated this problem even in near-vertical wells.
Rotary drag-caused drilling and completion problems become much more pronounced for wells at deviated angles from the vertical, especially extended reach wells. In addition to the potential for bit whirl problems at the drill bit, the rotary frictional drag generated by the drill string becomes very significant, especially when using heavy weight drill strings in nearly horizonal wellbores. As the wellbore extends further out, the rotary drag on the drill string (or other tubulars in the well) may even preclude rotation, e.g., the rotary force required to overcome the torsional drag exceeds the torsional strength of the drill string causing (twist-off) failure. Since the diameter and weight of a casing/liner string being set is typically larger and heavier than a drill string, the torsional forces needed to rotate the casing or liner can be even greater than that required to rotate a drill string and/or greater than the available rotary torque.
Common drilling and completion methods for overcoming tubular rotary drag either 1) use conventional drill pipe rubbers, or 2) reduce the sliding frictional forces along the string, e.g., by lubrication. In the first method, pipe centralizers, standoffs or other means for minimizing pipe/wellbore contact area are attached along the length of the drill string. But for nearly horizontal wellbores, the increased forces at the centralizers or other small contact area devices have the potential for damaging the wellbore and increasing axial drag when the tubulars are slid into the wellbore. This damage potential has generally precluded application of this drag reducing method to typical extended reach wells.
Other frictional reducing methods lubricate or otherwise reduce the coefficient of friction. These lubricating methods are limited in effectiveness since the coefficient of friction cannot be reduced to zero. Other frictional reducing methods include flotation methods and devices such as described in U.S. Pat. Nos. 4,986,361; 5,117,915; and 5,181,571, which are herein incorporated by reference. These prior methods do allow longer deviated boreholes, but as longer deviated boreholes are needed, unacceptable drag problems may still be generated.